SPE/Petroleum Society of CIM 65464
`
`Application of Hydraulic Fractures in Openhole Horizontal Wells
`P. D. Ellis, SPE, Golden Okie Associates, Inc., G. M. Kniffin, SPE, and J. D. Harkrider, SPE, Apex Petroleum Engineering
`
`Copyright 2000, SPE/PS-CIM International Conference on Horizontal Well Technology
`
`This paper was prepared for presentation at the 2000 SPE/Petroleum Society of CIM Inter-
`national Conference on Horizontal Well Technology held in Calgary, Alberta, Canada, 6-8
`November 2000.
`
`This paper was selected for presentation by an SPE/PS-CIM Program Committee following
`review of information contained in an abstract submitted by the author(s). Contents of the
`paper, as presented, have not been reviewed by the Society of Petroleum Engineers or the
`Petroleum Society of CIM and are subject to correction by the author(s). The material, as
`presented, does not necessarily reflect any position of the Society of Petroleum Engineers, the
`Petroleum Society of CIM, their officers, or members. Papers presented at SPE/PS-CIM
`meetings are subject to publication review by Editorial Committees of the Society of Petroleum
`Engineers and Petroleum Society of CIM. Electronic reproduction, distribution, or storage of
`any part of this paper for commercial purposes without the written consent of the Society of
`Petroleum Engineers is prohibited. Permission to reproduce in print is restricted to an abstract
`of not more than 300 words; illustrations may not be copied. The abstract must contain
`conspicuous acknowledgment of where and by whom the paper was presented. Write
`Librarian, SPE, P.O. Box 833836, Richardson, TX 75083-3836, U.S.A., fax 01-972-952-9435.
`
`Abstract
`This paper describes a process that has improved production,
`reduced costs, saved time, and dramatically improved the
`results of fracture stimulating low permeability horizontal
`wells. The use of both propped and acid fracture treatments
`will be described.
`
`The process has been used for openhole completions aligned
`in the approximate direction of fracture propagation as well as
`for fractures transverse to the well bore. The technique has
`effectively eliminated well bore connectivity problems that
`had been observed in vertical completions and cased and
`cemented horizontal wells with transverse fractures.
`
`The process has been used to increase production over 25
`fold in a 30 year old field. It has also proven successful in a
`marginally economic field that had been completed using
`propped fractures in vertical wells.
`
`The procedure employs a system of multiple, retrievable
`treating subs that are specifically tailored to a unique well bore
`configuration and allow treating the entire interval with a
`single stage. The treating subs are designed to distribute the
`treating fluid as desired along the length of the lateral. The
`process has been successfully used in over 100 wells and
`laterals in fields located in California, Illinois, New Mexico,
`Utah, and Texas.
`
`Introduction
`History of Horizontal Wells1,2. Horizontal and high angle
`wells have been envisioned and/or used for approximately 80
`
`years. Patents were filed in the early 1920’s in the United
`States, but the tools were never fully developed. Horizontal
`wells re-emerged in the 1940’s and 50’s, but were displaced
`when hydraulic fracturing was developed in the late 1940’s
`and early 50’s. Horizontal wells were used in the Soviet
`Union and China during the 1950’s and 60’s. A heightened
`interest in horizontal well resurfaced in the late 1970’s due to
`the increased directional control developed for offshore
`drilling. By 1985 further advances in horizontal drilling
`techniques and production response led to a boom in
`horizontal wells.
`
`Well Paths1. Many different well paths are considered
`“horizontal” besides a flat path. Common trajectories include
`inclined, both up and down, wavy or undulating, multilevel,
`and multilateral, or depending on the application very
`complicated. Fig. 1 shows some of the more common well
`paths.
`
`Common Uses1,2,3. Horizontal wells increase production by
`contacting more reservoir rock; intersecting natural fractures;
`reducing gas or water coning at a given production rate or
`drawdown; improving sweep efficiency in secondary and
`tertiary recovery projects; and improving gravity drainage in
`low pressure reservoirs. Ideally, the horizontal well should be
`completed openhole to take full advantage of the increased
`reservoir contact. This is not always possible due to wellbore
`stability problems or undesired fluid entry.
`BAKER HUGHES INCORPORATED
`Unstimulated Wells1,3. Horizontal wells are cost effective
`AND BAKER HUGHES OILFIELD
`where the reservoir permeability is sufficient, damage is not
`excessive, or sufficient natural fractures are encountered to
`OPERATIONS, INC.
`produce economically. Completions are relatively simple
`Exhibit 1032
`when these key parameters are encountered and stimulation,
`BAKER HUGHES INCORPORATED
`isolation of undesired gas/water, or wellbore stability is not a
`problem. However, when these problems exist, the complexity
`AND BAKER HUGHES OILFIELD
`of the horizontal completion increases dramatically. Isolation
`OPERATIONS, INC. v. PACKERS
`requires that additional hardware such as external casing
`packers, scab liners, screens, slotted liners, etc. be used in an
`PLUS ENERGY SERVICES, INC.
`effort to eliminate the unwanted reservoir problem.
`IPR2016-00596
`Typically, the most common method of isolation is
`cementing casing in the horizontal. Unfortunately, this
`isolates not only the problem but also the reservoir from the
`
`Page 1 of 10
`
`

`

`SPE/Petroleum Society of CIM 65464
`
`Application of Hydraulic Fractures in Openhole Horizontal Wells
`P. D. Ellis, SPE, Golden Okie Associates, Inc., G. M. Kniffin, SPE, and J. D. Harkrider, SPE, Apex Petroleum Engineering
`
`Copyright 2000, SPE/PS-CIM International Conference on Horizontal Well Technology
`
`This paper was prepared for presentation at the 2000 SPE/Petroleum Society of CIM Inter-
`national Conference on Horizontal Well Technology held in Calgary, Alberta, Canada, 6-8
`November 2000.
`
`This paper was selected for presentation by an SPE/PS-CIM Program Committee following
`review of information contained in an abstract submitted by the author(s). Contents of the
`paper, as presented, have not been reviewed by the Society of Petroleum Engineers or the
`Petroleum Society of CIM and are subject to correction by the author(s). The material, as
`presented, does not necessarily reflect any position of the Society of Petroleum Engineers, the
`Petroleum Society of CIM, their officers, or members. Papers presented at SPE/PS-CIM
`meetings are subject to publication review by Editorial Committees of the Society of Petroleum
`Engineers and Petroleum Society of CIM. Electronic reproduction, distribution, or storage of
`any part of this paper for commercial purposes without the written consent of the Society of
`Petroleum Engineers is prohibited. Permission to reproduce in print is restricted to an abstract
`of not more than 300 words; illustrations may not be copied. The abstract must contain
`conspicuous acknowledgment of where and by whom the paper was presented. Write
`Librarian, SPE, P.O. Box 833836, Richardson, TX 75083-3836, U.S.A., fax 01-972-952-9435.
`
`Abstract
`This paper describes a process that has improved production,
`reduced costs, saved time, and dramatically improved the
`results of fracture stimulating low permeability horizontal
`wells. The use of both propped and acid fracture treatments
`will be described.
`
`The process has been used for openhole completions aligned
`in the approximate direction of fracture propagation as well as
`for fractures transverse to the well bore. The technique has
`effectively eliminated well bore connectivity problems that
`had been observed in vertical completions and cased and
`cemented horizontal wells with transverse fractures.
`
`The process has been used to increase production over 25
`fold in a 30 year old field. It has also proven successful in a
`marginally economic field that had been completed using
`propped fractures in vertical wells.
`
`The procedure employs a system of multiple, retrievable
`treating subs that are specifically tailored to a unique well bore
`configuration and allow treating the entire interval with a
`single stage. The treating subs are designed to distribute the
`treating fluid as desired along the length of the lateral. The
`process has been successfully used in over 100 wells and
`laterals in fields located in California, Illinois, New Mexico,
`Utah, and Texas.
`
`Introduction
`History of Horizontal Wells1,2. Horizontal and high angle
`wells have been envisioned and/or used for approximately 80
`
`years. Patents were filed in the early 1920’s in the United
`States, but the tools were never fully developed. Horizontal
`wells re-emerged in the 1940’s and 50’s, but were displaced
`when hydraulic fracturing was developed in the late 1940’s
`and early 50’s. Horizontal wells were used in the Soviet
`Union and China during the 1950’s and 60’s. A heightened
`interest in horizontal well resurfaced in the late 1970’s due to
`the increased directional control developed for offshore
`drilling. By 1985 further advances in horizontal drilling
`techniques and production response led to a boom in
`horizontal wells.
`
`Well Paths1. Many different well paths are considered
`“horizontal” besides a flat path. Common trajectories include
`inclined, both up and down, wavy or undulating, multilevel,
`and multilateral, or depending on the application very
`complicated. Fig. 1 shows some of the more common well
`paths.
`
`Common Uses1,2,3. Horizontal wells increase production by
`contacting more reservoir rock; intersecting natural fractures;
`reducing gas or water coning at a given production rate or
`drawdown; improving sweep efficiency in secondary and
`tertiary recovery projects; and improving gravity drainage in
`low pressure reservoirs. Ideally, the horizontal well should be
`completed openhole to take full advantage of the increased
`reservoir contact. This is not always possible due to wellbore
`stability problems or undesired fluid entry.
`
`Unstimulated Wells1,3. Horizontal wells are cost effective
`where the reservoir permeability is sufficient, damage is not
`excessive, or sufficient natural fractures are encountered to
`produce economically. Completions are relatively simple
`when these key parameters are encountered and stimulation,
`isolation of undesired gas/water, or wellbore stability is not a
`problem. However, when these problems exist, the complexity
`of the horizontal completion increases dramatically. Isolation
`requires that additional hardware such as external casing
`packers, scab liners, screens, slotted liners, etc. be used in an
`effort to eliminate the unwanted reservoir problem.
`
`Typically, the most common method of isolation is
`cementing casing in the horizontal. Unfortunately, this
`isolates not only the problem but also the reservoir from the
`
`Page 1 of 10
`
`

`

`2
`
`P. D. ELLIS, G. M. KNIFFIN, J. D. HARKRIDER
`
`SPE/PS-CIM 65464
`
`wellbore. Though selective perforating may re-establish
`communication with
`the reservoir, restoring production
`usually is more difficult. If the matrix permeability is
`sufficient, productivity may not be lost. However, if the
`production comes primarily from natural fractures, perforating
`into the natural fractures to restore production is highly
`unlikely. Regardless of the perforating technique, once
`cemented, stimulating the lateral becomes the dominant
`variable in a horizontal well completion.
`
`Matrix Stimulation1,3. While many wells can be completed
`with no stimulation, the extended time required to drill a
`horizontal well of several thousand feet compared to drilling a
`vertical well through the comparatively thin pay zone can
`result in damage that must be removed in order to have an
`economic completion. Aside from the issue of damage
`identification and the subsequent fluid selection, the critical
`operational issue is effectively distributing the cleanup fluid
`along the entire horizontal section.
`
`Pump time for a matrix stimulation of a horizontal well
`can be ten times or more than a vertical well depending on the
`ratio of lateral length to vertical pay. A vertical well with 100
`ft of pay zone treated using 100 gal/ft at one-half bpm requires
`approximately 8 hours pumping time.
` By analogy, a
`horizontal well with 1,000 ft of section would require over 80
`hours of pumping to give an equivalent treatment if the rate
`could not be increased. Fortunately, the increased length
`allows the rate to be increased depending on the ratio of
`horizontal to vertical permeability. For a horizontal to vertical
`permeability ratio of ten, the rate could be tripled for the
`horizontal well reducing the time to approximately 24 hours.
`
`The two most common placement methods for matrix
`stimulation are bullheading and moving tubing/coiled tubing
`through the horizontal wellbore. While treating the entire
`section is important in a vertical well, it is essential in
`horizontal completions. Thus, diversion, either mechanical or
`chemical, is required for matrix stimulations. Straddle packers
`or packer/retrievable bridge plug assemblies conveyed by
`tubing or coil tubing can provide effective mechanical
`isolation to a portion of the horizontal. Though limited in
`openhole completions, this type of mechanical isolation is
`most
`effective
`in
`cased,
`cemented,
`and perforated
`completions. Chemical diverters such as benzoic acid flakes,
`rock salt, wax beads, foams, gels, etc. are often used in
`openhole and slotted
`liner completions with marginal
`effectiveness. However whether mechanical or chemical
`diversion is used, the completion time is significantly
`increased. Multiple sets of packers, packer failures, tubing or
`coiled tubing movement, reduced injection rates required
`when using chemical diverters or small diameter tubing, all
`exponentially increase the time required to matrix stimulate
`the horizontal well. To eliminate these diversion issues and
`costs, many operators employ bullheading techniques to
`stimulate the horizontal. Though cost effective, coverage of
`
`the lateral is sacrificed and subsequent production results can
`be disappointing.
`
`Hydraulic Fractures1,2,3,4. Though advances
`in drilling
`systems made horizontal wells attractive by the mid-80’s,
`horizontal well stimulation was not an unqualified success.
`Major
`issues
`included wellbore
`stability
`in uncased
`horizontals, cement bond quality when cementing horizontal
`wellbores, cost effective methods to isolate individual stages,
`unique stress fields induced around the borehole causing
`excess skin/pressure signatures, and the preferred direction of
`fracture propagation
`relative
`to wellbore orientation
`(longitudinal or transverse).
`
`Treatment Type. These issues continue being important
`considerations
`in completing horizontal wellbores using
`hydraulic fracture treatments today. If the horizontal is
`stimulated with either acid or water fracture treatments,
`methods employed in matrix stimulation are applicable
`including a heel and toe variation using tubing run to the end
`of the lateral.
`
`For propped fracture treatments, however, pipe is usually
`cemented and perforated to perform the fracture treatment.
`Concerns about wellbore stability, isolation between stages,
`and fishing stuck pipe in an openhole environment are the
`primary reasons for cementing casing in the horizontal
`wellbore. When multiple transverse fractures are placed,
`common practice is to pump multiple stages with mechanical
`isolation between stages5.
` Also, multiple stages with
`mechanical isolation have been used in cemented and
`perforated wells for longitudinal fractures6.
`
`In addition, when pumping a propped fracture treatment in
`a cased, cemented, and perforated horizontal well, high
`breakdown and treating pressures have been reported and are
`prone to premature screenouts if not mitigated. These
`problems have generally been attributed to tortuosity (turning
`of the fracture), multiple competing fractures, or a poor
`cement job. Common techniques to minimize the near-
`wellbore effects include pumping proppant slugs, breaking
`down the formation with cross-linked gel, and extreme
`overbalanced perforating prior to pumping the main fracture
`treatment5,7,8.
`
`Within the past few years, a new emphasis has been placed
`on using propped fractures in the openhole environment.
`Several proposals have been put forward in addition to the
`process discussed here.
`
`Longitudinal or Transverse Fractures2,3,4,9. The orientation
`of
`the
`induced fracture relative
`to
`the wellbore,
`i.e.
`longitudinal or transverse, is also of great importance in
`horizontal completions. To illustrate the concept, Fig. 2
`shows a longitudinal fracture and multiple transverse fractures
`for a horizontal well.
`
`Page 2 of 10
`
`

`

`SPE/PS-CIM 65464
`
`APPLICATION OF HYDRAULIC FRACTURES IN OPENHOLE HORIZONTAL WELLS
`
`3
`
`Many reservoir simulation studies comparing the predicted
`response of a vertical fractured well to a horizontal well with
`either a longitudinal fracture or multiple transverse fractures
`have been performed. In most comparisons, the vertical well
`is assumed to have a fracture half length equal to one-half the
`horizontal well length. With this assumption, it is difficult to
`economically justify drilling a horizontal well having a
`longitudinal fracture orientation unless the vertical well has a
`finite conductivity fracture. Similarly, reservoir simulation
`studies have shown that multiple transverse fractures are
`required to justify the increased cost of drilling the horizontal
`well and to offset the choke effects caused by the limited
`contact of the fracture with the wellbore and/or re-orientation
`of the fracture away from the wellbore.
`
`A vertical well with an infinitely conductive, 1,000 ft half
`length fracture would, therefore, be more economic than a
`2,000 ft horizontal well with a full longitudinal fracture
`according to these simulations. Unfortunately, production
`modeling and pressure transient testing of vertical fractured
`wells have not consistently confirmed the ability to achieve an
`effective fracture half length of 1,000 ft. Actual results are
`often in the 200 ft to 300 ft range and occasionally in the 50 ft
`fracture half length range. Reasons for the shorter effective
`fracture length are documented in the literature but could
`include any or all of the following reasons: height growth out
`of the designed interval; multiple fractures either from a single
`set of perforations or from multiple sets of perforations that
`fail to connect together; or residual gel damage. Thus,
`effective completion of a 2,000 ft horizontal well with a
`longitudinal fracture could in fact be more economical than a
`vertical fractured well.
`
`To illustrate this point with a simplistic comparison,
`consider the fracture area within the pay zone for the vertical
`well assuming 100 ft of vertical section and a 250 ft effective
`fracture half length compared to a 2,000 ft horizontal well
`with a 50 ft (vertically) fracture half length. For the vertical
`well, the cross-sectional fracture area (one face only) is
`2x250x100 or 50,000 ft2. For the horizontal well, the area is
`2x2000x50 or 200,000 ft2. Thus, it would take four vertical
`fractured wells to yield the same fracture area as the one
`horizontal well. Assuming that transverse fractures would be
`equivalent in length to the vertical well fracture and ignoring
`the choke effects for limited wellbore contact and/or fracture
`re-orientation, it would also take four transverse fractures to
`equal the area of the single longitudinal fracture. To more
`accurately assess whether the longitudinal fracture or multiple
`transverse fractures would be more economic requires a
`detailed reservoir simulation comparing these two scenarios.
`
`It should also be noted that, for the horizontal well with a
`longitudinal
`fracture, only one-fifth of
`the
`fracture
`conductivity of the vertical well is required to achieve an
`infinitely conductive fracture due to the shorter fracture length
`required to reach the upper and lower boundaries of the
`reservoir.
`
`Experiences with Propped Fractures in Horizontal
`Wells
`By the mid 1990’s, horizontal wells were being used
`successfully in a number of areas. The Austin Chalk of Texas
`was often touted as example of successful wells as were wells
`in the Dan Field of the North Sea, to name but two.
`
`With these successes, some in the industry began to believe
`that horizontal wells could cure all our reservoir quality ills
`and possibly eliminate the need for hydraulic fractures in low
`permeability formations, particularly if natural fractures could
`be intersected. This was not to be in all cases however. Many
`wells that were drilled in anticipation of encountering natural
`fractures failed to do so. Then came the question: “how can
`this well be salvaged?” For these low permeability wells, the
`only option besides abandonment was a hydraulic fracture
`treatment. Then came the problem: “how can this well be
`effectively stimulated?”
`
`Table 1 lists the average reservoir properties for the four
`fields to be discussed in this presentation.
`
`Near-Wellbore Connection Problems. Even in areas, such
`as the Dan Field, where successful application of propped
`hydraulic fractures to horizontal wells has been documented,
`mitigating near-wellbore connection problems was essential
`for effective stimulation. Completion procedures such as acid
`breakdowns, high viscosity slugs, proppant slugs and
`overbalanced perforating have been implemented in vertical
`wells to successfully address the near-wellbore connection
`problem5,6,7. Three projects are discussed to illustrate the
`application of these procedures in horizontal completions,
`with varying degrees of success.
`
`The first case study is a newly drilled gas well in the Red Oak
`formation of southeast Oklahoma. The second case study is a
`re-entry project of three oil wells in the Gallup formation of
`northwest New Mexico. The third case study was a five well
`project in the Monterey formation in Kern County, California.
`Table 1 lists the average reservoir properties of the Red Oak,
`Gallup, and Monterey formations. Vertical wells in all three of
`these formations require propped fractures
`to establish
`production. Both the Red Oak and Gallup horizontals were
`completed using generally accepted procedures while the
`Monterey wells used the patent pending process.
`
`Red Oak. In the Red Oak horizontal, the geologic expectation
`was to cross natural fractures and yield economic production
`without fracture stimulation. Natural fractures were not
`encountered and production was uneconomic from
`the
`openhole. Thus, the contingency plan to set and cement a
`liner to pump multiple transverse fractures was implemented.
`
`After cementing the liner, short intervals (2 to 3 ft) of
`highest bond were selected for perforating to reduce the
`possibility of developing multiple competing fractures within
`
`Page 3 of 10
`
`

`

`4
`
`P. D. ELLIS, G. M. KNIFFIN, J. D. HARKRIDER
`
`SPE/PS-CIM 65464
`
`the interval. Tubing-conveyed perforating guns with high shot
`density and large diameter holes were used.
`
`horizontal, wellbore to fracture communication was impaired
`as breakdown pressures and near-wellbore effects were high.
`
`A perforation breakdown test using linear gel was pumped
`to determine
`the
`extent of
`the near-wellbore or
`fracture/wellbore connectivity problems using gel. Initially,
`the formation could not be broken down as pressures exceeded
`the anticipated 5,000 psi, which is the typical treating pressure
`for vertical wells. Tubing was tied into the liner and the
`formation finally broke down at a pressure in excess of 9,000
`psi. Two proppant slugs were pumped to condition the
`wellbore to fracture connectivity, followed by the nitrogen
`foamed
`fracture
`treatment.
` Screenout occurred with
`approximately 20% of the designed proppant volume placed.
`Subsequently, the horizontal was re-fractured using a borate
`cross-linked gel. Approximately 30% of the designed
`proppant volume was pumped prior to flushing due to high
`treating pressures.
`
`For the second stage, proppant slugs in both linear and
`borate cross-linked gels were planned before attempting the
`main fracture treatment. These procedures were designed to
`mitigate
`the wellbore
`to fracture connectivity problem.
`Though the subsequent treating pressures were greatly reduced
`as a result, and the propped fracture treatment successfully
`placed 6 to 8 ppg, the mitigating procedure was costly,
`requiring several additional days of rig and pumping time.
`
`For the third stage, extreme overbalanced perforating
`(EOB) was used in an attempt to reduce the near-wellbore
`problems and minimize the time and fluid volumes required to
`condition the near-wellbore connection. The near-wellbore
`problem was significantly reduced using EOB as
`the
`breakdown and treating pressures were the lowest of the three
`stages. The improvement was dramatic as a lower viscosity
`CO2 foam system successfully placed 10 ppg in the fracture.
`Though EOB is an effective technique for mitigating the near-
`wellbore connectivity problem, it potentially increases the far-
`field fracture complexity which in itself may contribute to
`premature screenouts.
`
`Gallup. In the second case study, three horizontal re-entries
`were drilled to intersect natural fractures with the intention of
`eliminating the need for fracture stimulation. Again, no
`natural fractures were encountered. Two of the wells were
`acid stimulated unsuccessfully in the openhole as formation
`stability problems arose after the acid treatments. In the third
`re-entry, a
`liner was set, cemented, and perforated.
`Subsequently two transverse fracture treatments were pumped.
`
`As this was a re-entry, a small 3-1/2 inch liner was set.
`Coiled tubing was used for logging, perforating, cleanout, and
`setting bridge plugs for isolation between fracture treatments.
`Short intervals were again perforated, but EOB could not be
`used due to the limitations of the available coiled tubing.
`Similar
`to
`the mechanisms observed
`in
`the Red Oak
`
`Proppant slugs reduced the near-wellbore problems, but
`the first fracture treatment screened out when 6 ppg proppant
`laden fluid hit the formation. Approximately 56% of the
`designed volume was placed in the fracture. For the second
`stage, identifying the near-wellbore connection problem early
`resulted in using an acid soak on the perforations and
`incorporating proppant slugs during the treatment. These
`mitigating procedures further reduced the treating pressure and
`proppant concentrations up to 6 ppg were successfully placed.
`.
`New Approach Required. In both of these projects, the costs
`and subsequent production results raised concerns about the
`viability of horizontal wells in tight formations. A different
`approach was required to make a successful well or the
`application of horizontal wells in tight formations would be
`discontinued. Development of the process will be discussed
`after the dramatic reduction of near-wellbore effects is shown
`with the Monterey horizontals.
`
`Monterey. This horizontal project was initiated because of
`marginal economics from an exploration and development
`package of the Monterey shale. Six vertical wells had been
`drilled and fracture stimulated with a maximum proppant
`concentration of less than 8 ppg. Near-wellbore problems
`were encountered in the vertical wells, and in some cases,
`resulted in premature screenouts with only 25% of the
`designed proppant volume placed. To illustrate the near-
`wellbore fracture complexity, Fig. 3 shows a pump-in step
`down test on well V-1. Based on the annular/dead string
`pressure, approximately 1,200 psi of near-wellbore pressure
`effects were measured at 18 bpm. Fig. 4 demonstrates the
`severe nature of these wellbore to fracture connection
`problems as the well screens out as when a one-half ppg
`proppant slug reaches the formation. Similar near-wellbore
`problems were observed in well V-2 although no annular
`pressure could be measured. Fig. 5 shows the main fracture
`treatment for well V-2. Notice the pressure inflection as 6 ppg
`first enters the perforations and suggests proppant was
`bridging asymmetrically. The treatment eventually screens
`out due in part to the poor near-wellbore connection.
`
`In order to improve the economics of this field, a
`horizontal well was proposed. The initial plan was to cement
`a liner and to pump multiple transverse fractures. Based on
`the high near-wellbore problems seen in the Red Oak and
`Gallup horizontal wells,
`the successes completing
`the
`Devonian wells noted below, and the near-wellbore problems
`of the offsetting vertical wells, the plan was significantly
`revised. The well path was re-aligned to the anticipated
`fracture direction and the completion was changed to an
`openhole, single stage fracture stimulation using the process
`developed. Fig. 6 shows a pump-in step down test for the first
`horizontal well. A dramatic improvement in the wellbore to
`fracture connection is indicated as near-wellbore effects are
`
`Page 4 of 10
`
`

`

`SPE/PS-CIM 65464
`
`APPLICATION OF HYDRAULIC FRACTURES IN OPENHOLE HORIZONTAL WELLS
`
`5
`
`negligible when the rate is stepped down from approximately
`50 bpm to zero. It should be noted that the annular pressure
`here is the true formation face pressure as the pressure drop
`across the diverting subs is between the treating string and the
`annulus. Fig. 7 shows the main treatment for this well. The
`pressure response indicates minimal asymmetric bridging
`character as the proppant concentration is increased from 2 to
`14 ppg. In fact, when an inadvertent 20 ppg stage was
`pumped, the bottomhole treating pressure shows only a slight
`increase and suggests that the wellbore to fracture connection
`was not a hindrance to high proppant concentrations.
`
`Openhole Fractures and Process Development
`The high costs and less than desired production performance
`of the Red Oak and Gallup horizontal wells using multiple
`transverse propped fractures led to a re-assessment of
`horizontal completion techniques being used. Openhole, high
`rate acid and water fracture treatments had been successfully
`used in naturally fractured fields such as the Austin Chalk.
`Could they be applied to other formations lacking natural
`fractures?
`
`Devonian. As the Red Oak and Gallup horizontal projects
`were coming to conclusion, a third project in the Devonian
`limestone in west Texas, was being tested with a horizontal
`well. Ten vertical wells had been drilled and fracture
`stimulated in the prior year to increase production from this 30
`year old field. Nine wells had used propped fractures and one
`had been completed with an acid fracture due to problems
`associated with placing proppant in the formation. Unit
`production had been increased from 2 mmcfd to a peak of over
`6 mmcfd after the ten vertical well program. The high decline
`rate and mixed results from the vertical wells due to several
`screenouts gave impetus to attempt a horizontal well. A re-
`entry of one of the newly drilled vertical wells was selected
`for the horizontal to increase drainage area, reduce the decline
`rate, and minimize costs.
`
`The vertical well selected for this test was making less
`than 10 mcfd prior to re-entry. Openhole tests of the
`horizontal lateral failed to produce after four days of
`swabbing. Based on the results of the Red Oak and Gallup
`horizontal wells, the screenouts of the vertical wells, and the
`successes in other carbonate reservoirs, it was decided to
`stimulate the openhole with a pad and acid fracture in a single
`stage.
`
`Fracture Orientation and Wellbore Configuration.
`Anticipated fracture direction was N 75-85 E and the well had
`been drilled within approximately 10-20 degrees of this
`direction. Thus it appeared that a mostly longitudinal fracture
`would be developed. Due to the anticipated longitudinal
`fracture, straddle packers were not considered. Bullheading
`was an option, but incomplete coverage had been seen in other
`locations10.
`
`A heel and toe fracture was therefore selected to insure
`that the toe of the well was treated. The toe was initially
`broken down and
`then
`the
`treatment was pumped
`simultaneously down both the tubing and annulus. A single
`treatment was used for the entire horizontal section and no
`near-wellbore problems were observed. Production was
`increased from 10 mcfd to 7.3 mmcfd at 1200 psi. Calculated
`AOF was 30 mmcfd.
`
`A second well was then re-entered and the direction was
`modified slightly to align more with the anticipated fracture
`direction. It was fracture stimulated in a similar manner and
`produced 6.8 mmcfd at 1650 psi with a CAOF of 38 mmcfd.
`
`the Lateral.
`Tre